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As the natural gas hydrate (NGH) resources show a bright future, more and more commercial and technical focuses have been devoted to this area. The low productivity, the sanding problem, and the poor economic performance are vital problems hindering the long‐term commercial exploration and development of NGS sediments. Among all these problems, the sanding problem can aggravate the low productivity and the poor economic efficiency problems. Therefore, it is necessary to investigate and tackle the sanding problem for the safe, long‐term, and large‐scale commercial development of offshore NGH resources. The sanding problem of the NGH sediment is highly related to the mechanical behavior of sediment. The main influencing factors are discussed, which are hydrate saturation, effective confining pressure, sand content, hydrate distribution, and multiple‐physical fields. This article summarizes the current research achievements systematically to determine how these factors affect sand production in NGH sediments. Besides the macrolevel about mechanical behaviors of NGH sediment, the sand motion modeling is also included in this review. The source of sand production is the free‐moving sand which comes from formation deformation. The review compares most commonly used yield criteria and then recommends a proper one for NGH sediments. The paper subsequently discusses the common investigation methods for the sanding problem in this area, including numerical simulation and experiments. The design and effect of sand control techniques have also been reviewed and discussed. According to the review results, the paper concludes the current research drawbacks and generates suggestions for future research. The novel methods of sand control investigation are machine learning and optimization methods.

Perforating-test joint operation in oil&gas wells may causes strong impact vibration of downhole tools which can easily lead to buckling of tubing string, falling off of tools and damage of instruments. A 3D impact dynamic model of the perforated tubing string is established by using d'Alembert's principle and microelement method, and solved by the Newton difference method, taking into account the well trajectory, internal/external fluid pressure, interaction forces between the tubing and casing, and the coupling effect of perforating gun-shock absorber-tubing string. Due to the complexity of the verification, firstly, a similar experiment is carried out to test the accuracy of the model preliminarily. Secondly, through a case analysis, the feasibility of the model in the perforation impact dynamic analysis of tubing string in curved wells is further investigated. Both the two tests show that the model proposed in this paper has good calculation accuracy and can meet the needs of perforation shock vibration analysis of tubing string in curved wells perforation.

Intelligent wells equipped with the interval control valve (ICV), which have the potential applications to significantly improve oil production or control the water production of wells and fields, are more and more widely utilized in the oilfields. The radial metal seal of an ICV is intended to isolate the flow of produced fluids between the casing annulus and the well tubing. The contact mechanical behaviors of the radial metal seal are essential to the structural design and reliability of ICVs in the intelligent well. In this paper, the two‐dimensional axisymmetric assembly of the radial metal seal and the closure member is abstracted as a combination of interference fit model and cantilever beam model. Based on that, the related theoretical model, between the radial metal seal's contact stress and its independent variables, has been derived. Next, numerically simulations of contact stress between the radial metal seal and the closure member for different independent variables are conducted by the finite element method (FEM) to validate the theoretical model. It is found that the mean absolute value of relative error between the numerical and theoretical results of the contact stress is approximately 10%. Additionally, the structural parameters of the radial metal seal are proposed with the absolute value of relative error

In deep-water test conditions, the riser-test pipe system (RTS) is subject to the vortex induced effect on riser, flow induced effect on test pipe and longitudinal/transverse coupling effect, which is prone to buckling deformation, fatigue fracture and friction perforation. To resolve this, the three-dimensional (3D) nonlinear vibration model of deep-water RTS is established using the micro-finite method, energy method and Hamilton variational principle. Based on the elastic-plastic contact collision theory, the nonlinear contact load calculation method between riser and test pipe is proposed. Compared with experimental measurement results, calculation results of the proposed vibration model in this study and the single tubing vibration model in our recent work, the correctness and effectiveness of the proposed vibration model of the deep-water RTS are verified. Meanwhile, the cumulative damage theory is used to establish the fatigue life prediction method of test pipe. Based on that, the influences of outflow velocity, internal flow velocity, significant wave height, as well as top tension coefficient on the fatigue life of test pipe are systematically analyzed. The results demonstrate that, first, with the increase of outflow velocity, the maximum alternating stress, the annual fatigue damage rate increased and the service life decreased significantly. The locations where fatigue failure of the test tube is easy to occur are mainly distributed at the upper “one third” and the bottom of test pipe. Second, with the increase of internal flow velocity, the “one third effect” of the test pipe will decrease, and is shown “the bottom damage effect”, which needs the attention of field operators. Third, during field operation, it is necessary to properly configure the top tension coefficient so that there can be a certain relaxation between the riser and the test pipe, so as to cause transverse vibration and consume some axial energy and load. The study led to the formulation of a theoretical method for safety evaluation and a practical approach for effectively improving the fatigue life of deep-water test pipe.

Annular pressure buildup (APB) is induced by high‐temperature tubing fluid heating the trapped annular fluid, which leads to liquid thermal expansion at the production stage in deepwater wells. Casing would be burst or collapsed without APB mitigation. A novel recovery relief method was adopted to mitigate APB through the principle of differential pressure. To assess the application effect of the method, APB prediction model and pressure relief threshold determination method were proposed, where the transient heat transfer and volume and pressure coupling were involved. The laboratory test of the principle prototype was conducted so that the feasibility of the recovery relief method was validated. The numerical APB mitigation effect was simulated by the field example. The production simulation results indicated that the high‐temperature‐induced APB caused casing failure. The simulation of APB mitigation with both inward and outward directions demonstrated that the casings using outward mitigation method were safer with lower safe factor. Besides, comparing the mitigating effect to the rupture disk, the recovery relief method had more maximum allowable APB of annulus A. Additionally, compared to other 11 ordinary mitigation methods with the qualities of engineering reliability, technology feasibility, and economy, the recovery relief method had best mitigation performance. Therefore, the recovery relief method was recommended for APB mitigating practice.

On one hand, a blowout test can clean the bottom of the well, and on the other, it can learn the productivity of the well, which is important work before putting the well into production and also the main basis for production allocation of the well. The accurate prediction of the blowout test process provides a theoretical basis for the design of a reasonable blowout test system and the determination of well cleaning time. During deepwater blowout tests, gas and liquid flows are unsteady in pipes, and flow parameters change over time. At present, accurately predicting changes in fluid temperature, pressure, liquid holdup, and other parameters in a wellbore during an actual blowout process using the commonly used steady-state prediction methods is difficult, and determining whether a test scheme is reasonable is impossible. Therefore, based on the conservation of mass, momentum, and energy during the blowout test process, in this study, formation, wellbore, and nozzle flows were coupled for the first time, and a time and space of unsteady pressure drop and a heat transfer differential equation system was established; furthermore, using the Newton–Raphson method, the equations were solved. Finally, the simulation of the transient flow of the blowout test was completed. Considering a measured deepwater gas well A as an example, the blowout test process was simulated, and the variations in the wellbore flow parameters were analyzed. Comparing the simulation result with the test data, we concluded the following. (1) During the blowout process, the wellbore temperature gradually increased; pressure at the bottom of the wellbore decreased; and pressure at the wellhead increased; and (2) the established model agreed well with the actual production data, and the average error of the wellhead pressure and temperature was less than 5%. Considering the high production capacity of deepwater gas wells, the use of large-sized tubing and nozzles to spray is recommended, which can improve the speed of clearing wells and prevent the formation of hydrate.

Intelligent wells armed with the interval control valve (ICV) are more and more widely applied in the oilfields. In an ICV, the metal seal pair composed of the metal seal ring and the sliding sleeve is designed to isolate the produced fluid flow between the casing annulus and the tubing. The evaluation of the metal seals for ICVs is necessary to enhance the reliability. In this paper, the influences of medium pressure and initial interference on the contact mechanical behaviors of the metal seal for the ICV are studied by using finite element analysis (FEA) when both of the metal seal pair elements have roundness errors. The results indicate that when the both long axes of the metal seal pair’s elliptical sections coincide or are orthogonal, the contact stresses on the core area for the seal face present cosine or sine curve distributions. Each distribution curve becomes smoother with the increase of medium pressure, initial interference or the reduction of sliding sleeve roundness error. And for the contact stress distribution curves, the maximum at the peaks and troughs and the average increase with the increase of the medium pressure, the initial interference and the roundness error of the sliding sleeve. Moreover, when the angle between the metal seal pair elliptical sections’ long axes increases from 0 ° to 90 °, the contact stress distribution curves on the core area for the seal face change from cosine to sine type, and the maximum at the peaks and troughs and the average first decrease and then increase. The relationship curves between the maximum or average contact stress and the angle of two long axes are approximately symmetrical about the line θ = 45° . This paper provides a simulation evaluation for the ICV metal seal pair with roundness error.

This work studied the effects of nano-SiO2 addition in drilling fluid on the wear behavior of casing. The disc specimens and pin specimens were made of 2Cr13 steel and G105 steel, respectively, and the water-based drilling fluids added with different amount of nano-SiO2 were tested, based on which, the wear rate, surface morphology, surface profile, and composition of the wear product were analyzed. Results showed that, the main wear mechanism of 2Cr13 steel casing in the drilling fluid is abrasive–corrosive wear. Adding nano-SiO2 to the drilling fluid can significantly reduce the casing wear. As the nano-SiO2 concentration increases, the wear rate and mean friction coefficient both increase first and then decrease. Drilling fluid shows best lubrication performance when the nano-SiO2 concentration is 2%. The shielding effect of nano-SiO2 can slow down the vicious cycle of “oxidation–destruction–reoxidation” during the wear process. Microhardness of tribofilms increases when adding more nano-SiO2 into drilling fluid, which increases the wear resistance of disc surfaces. However, the excessive addition of nano-SiO2 on a 2% concentration basis can lead to the decrease in bonding strength between tribofilms and matrix, leading to large delamination on the disc surface and therefore reducing the shielding effect of nano-SiO2.

A model is developed to investigate the dynamic behavior of a deepwater drilling platform riser system under emergency evacuation conditions. In the model, the riser in the ocean environment is modeled as a beam with coupled transverse and axial motions, and its upper and lower ends are respectively connected to the platform and to the lower marine riser package with hard joints. The fluid forces and the added mass and drag forces are modeled using a semi-empirical Morison equation, so the equations of the model are nonlinear, coupled, and multibody. The model is discretized in a finite element approach and solved using Newmark's method. Its validity is verified using ANSYS. Using the model, the influences of platform motion, riser suspension length, ocean load, and platform evacuation speed on the dynamic behavior of the riser are determined, and the results can provide theoretical support for the design and practical operation of hard suspension pipe strings.

Due to wear failures caused by tubing string vibrations in high-yield gas wells, an orthogonal wear experiment was performed on the 13Cr-L80 tubing string. The influence of contact load, friction frequency, wear time, completion fluid density, and reciprocating stroke length on the wear characteristics of the tubing string were effectively analyzed using range analysis, variance analysis and the control variable methods. The results demonstrate that, the wear patterns of the tubing-casing were primarily abrasive and adhesive wears, with minimal corrosion wear. In-field operations, the service life of the tubing string in high-yield gas wells can be effectively augmented by reducing the contact load and longitudinal vibration displacement of the tubing-casing, maintaining the vibration frequency of the tubing string below 1.5 Hz, and utilizing a completion fluid with a higher density (approximately 1.2 g/cm3). The wear amount and friction coefficient of the tubing string are primarily influenced by the contact load and reciprocating stroke length, respectively. Moreover, the effect significances of the contact load and reciprocating stroke length were particularly significant and significant, respectively. These results provide useful guidance for designing and implementing approaches to improve the service life of tubing strings in high-yield gas wells.

In the development of oil and gas fields, many wells have a phenomenon of wellhead growth originating in thermal stress of columns and cement sheaths poses severe challenges to shaft safety. Notably, the problem of wellhead growth is more serious in fully sealed oil and gas wells at sea. Therefore, this research on the wellbore cementation force, the wellbore lifting force, and wellhead growth for offshore oil and gas wells was critical. Based the effects on the comprehensive consideration of wellbore temperature change, annulus pressure, and performance parameters of cement sheath and casing, and then established the calculation method of cementing force, lifting force, and wellhead growth. Next, used the measured data and the data in the literature to validate the model. The results show that the calculation results of this model accord with the actual situation in the field. Finally, a gas well in the South China Sea was analyzed. Found that the increasing yield and annulus pressure will increase the height of wellhead growth, but the increasing thermal expansivity and the increasing elastic modulus of the cement sheath will decrease the height of wellhead growth. To avoid the wellhead growth, offshore oil and gas wells should adopt the submarine pipeline method (the height of the mud line relative to the deck was Zero). Thus, to improve the height of wellhead growth, the designed performance of the cement sheath, the management of annulus pressure, and the control of yield shall be introduced into the process of oil and gas field development.

Natural Gas Liquid (NGL) primarily contains light hydrocarbon components, e.g., ethane, propane and iso-butane. Its unique phase behavior and rapid evaporation process typically causes a non-equilibrium thermodynamic two-phase flow in the transmission pipeline, in which the liquid and vapor phases have different temperatures at the same cross section of the pipe. To describe this two-phase flow, a one-dimensional two-fluid model considering the NGL compressibility and viscosity is built based on the general mass, momentum and energy conservation equations for each phase. To select its appropriate solution method, the mathematical characteristic of the model is studied using the eigenvalue analysis method. The results demonstrate that its mathematical characteristic is primarily dependent on the void fraction, densities and flow velocities of the liquid and vapor phases. The two-fluid model is hyperbolic and well-posed when the liquid flow velocity is equal to the vapor flow velocity, the two-phase flow reduces to a single phase flow, or the difference between the liquid velocity and the vapor velocity is greater than the mixture sound speed. Otherwise, the model is non-hyperbolic and ill-posed. Additionally, the results indicate that the numerical solution methods of the adiabatic two-fluid model could be potentially extended to solve the non-equilibrium two-fluid model for the NGL pipe flow.

Predicting the hydrate formation condition is an important issue for determining high CO 2 content natural gas transport. The widely used Parrish-Prausnitz (P-P) model cannot predict the hydrate formation temperatures and pressures accurately for high CO 2 content natural gas. This paper introduced a simple correction factor into the P-P model, resulting in an improved P-P model. The analytical expression of this new parameter is developed by correlating the deviations of the predicted hydrate formation temperatures with the CO 2 molar fraction in the gas mixtures. A total of 140 sets of experimental data were applied to validate the proposed model, which covered wide pressure and CO 2 molar fraction ranges of 1.45–13.0 MPa and 0–90%, respectively. The results show that the improved P-P model balances a simple form with high accuracy. The average deviation of the improved P-P model is 0.098 °C, whereas that of the original P-P model is 2.424 °C. It is essentially comparable in its prediction ability to CSMGem software and the cell potential method when it is applied to predicting the hydrate temperatures of high CO 2 content natural gases.

Asset Integrity Management (AIM) technology has been rapidly developed and applied so that it has become a main management technology of offshore platform equipment and facilities. Risk identification and quantitative evaluation method is one of the core contents in the AIM. However, most of the existing methods are qualitative analysis results, simple analysis process, and strong subjectivity, which can no longer meet the development of AIM technology system. By analyzing disadvantages and shortcomings of the existing methods and adapting to the technology requirements of the AIM, a Streamline Failure Mode Effects and Criticality Analysis (SFMECA) was presented to achieve risk identification and quantitative evaluation based on the traditional FMECA and Borda scoring method. Taking a truss crane as a case study, feasibility and operability of the SFMECA were verified effectively with obtaining a detailed and complete analysis worksheet. Compared with their analysis process and worksheet, it was more specific, more comprehensive, and more operable by applying the SFMECA than the traditional FMECA. Moreover, in the SFMECA, failure risk was divided into four categories in detail and quantified separately to better distinguish and evaluate failure effect. Then a comprehensive quantitative evaluation method of four risks was carried out and risk knots in risk priority number (RPN) were obviously reduced, which help to develop more accurate risk management measures. Independent evaluation mechanism of multiple experts or teams is adopted in the SFMECA to make the analysis and evaluation results more objective. So the worksheet obtained through the SFMECA contains more quantitative data, comprehensive information, and objective results, which can better meet technical system of the AIM. Therefore, application of the SFMECA can provide technical support for extension and application of the AIM technology, including risk quantitative analysis, maintenance decision, and integrity evaluation, for offshore platform equipment and facilities.

This study has established a nonlinear flow-induced vibration (FIV) model of tubing string by using the micro-element method and energy method with the Hamiltonian variational principle, in order to address the vibration failure problem of the tubing string induced by high-speed fluid flow in the tubing of high temperature and high pressure (HPHT) oilg ②with the increase of the well inclination angle, the vibration response of the tubing string decreased to a certain extent. Regarding the influence of the well section length, the longitudinal vibration response of the tubing string was most sensitive to the length of the vertical section, followed by the steady inclined section, and finally the angle building section. Thus, during designing, the length of the vertical section should be reduced, while the length of the angle building section and the well inclination angle of the steady inclined section should be increased; ③As the position of the production packer moved up, the vibration responses of the lower and middle tubing strings both decreased, and the optimal packer position was between 3,549 and 3,666 m. The research results can serve as an effective analysis tool and provide a theoretical basis for the safety design of the tubing strings in the HPHT oil&gas well site.

In view of the fatigue failure of tubing string caused by fluid-induced vibration (FIV) in high-yield curved well, a nonlinear vibration model of tubing string is established using energy method and Hamilton principle, which considers the longitudinal/lateral coupling effect of tubing string and the nonlinear contact collision effect of tubing-casing and verified by a similar experiment of tubing vibration. The cumulative damage theory (Miner's Law) is used to establish the fatigue life prediction method of the tubing string in high-yield curved well combined with the stress response which was determined by the proposed vibration model and the S–N curve of the tubing material (13Cr-L80) which was measured by fatigue experiment. Based on that, the fatigue life of the tubing in two typical horizontal well and directional well was analyzed under different production rate (0.4–1.6 million square/day) and different tubing diameter (3.5-in and 4.5-in). The result shows that the most dangerous position of the tubing string appears between 3/4 position of the tubing string and the packer. The critical production rate of 4.5-in tubing string in horizontal well is 1.08 million square/day to satisfy the life requirements of gas reservoir tubing (20 years), and which is 0.45 million square/day in directional well. The fatigue life of 4.5-in tubing string is higher than that of 3.5-in tubing string in both horizontal and directional wells. The research results provide a theoretically sound guidance for designing and practically sound approach for effectively improving the service life of tubing string in high-yield curved wells.

The critical pressure ratio (ηc) is an essential parameter for computing the vapor-liquid two-phase critical pressure and mass flow rate of multicomponent hydrocarbon mixtures flowing through valves and leakage orifices. The Homogeneous Non-Equilibrium Diener-Schmidt (HNE-DS) model widely used to calculate ηc assumes that the fluid's volume linearly changes with the pressure (using the Clausius-Clapeyron equation), which is not suitable for multicomponent gas mixtures. In this paper, a new Homogeneous Non-Equilibrium (new-HNE) model is proposed to calculate ηc of gas mixtures. Firstly, a new critical flow compressibility factor (ωc) is developed from its thermodynamic definition and the Peng-Robinson equation of state (EOS), overcoming the inherent limitations of the Clausius-Clapeyron equation. Then, ηc is correlated to the newly derived ωc by fitting experimental data at various pressures and gas mass fractions of both single-component and multicomponent gas mixtures, yielding the new HNE-DS model. Results show that, for the water-steam and air-water two-phase flow, the average relative deviations (ARD) between the calculated critical pressure ratios and experimental values are equal to 2.8% and 4.93%, respectively, which represents a significant improvement in comparison with the original HNE-DS model. Moreover, this new model is extended to the applications of Liquefied natural gas (LNG)/liquefied petroleum gas (LPG) fluids, and will further contribute to the calculation of the leakage mass flow rate of fluid flowing through the orifices/valves.

During gas production at gas storage wells, the high-speed flow of gas results in the vibration of production pipe strings, thereby leading to changes in the mechanical properties of production pipe strings and their destruction. To study the dynamic characteristics of pipe strings in gas storage wells, a fluid–structure interaction analysis model for production pipe strings in gas storage was established by considering the interaction effect of gas and pipe strings in the lateral and longitudinal directions and solved by using the method of characteristic. The results of the proposed model were validated through a similar experiment and comparison with the simulation results of published studies. The field data of a gas storage well at the Huabei Oilfield were used as bases to discuss the effects of gas production rate, wellhead pressure, pipe string thickness, and gas density on the dynamic characteristics of pipe strings. Results show that pipe strings are subject to a large displacement at the well-opening moment, and then the pipe string vibration is gradually attenuated. A large lateral deformation occurs in the middle and lower part of the pipe string. Pipe string displacement and deformation increases with an increase in gas production rate and decrease with an increase in wellhead pressure and pipe string thickness. With the increases of gas density, the fluid–structure interaction between the string and the gas intensifies, resulting in the increase of the displacement caused by the string vibration. These findings are of significant importance in reducing the vibration of pipe strings and protecting them during gas storage well production.

This work investigated the effects of sliding speed on tribological behavior of AA 7075 petroleum casing in simulated drilling environment by pin-on-disc wear test. The main wear mechanism of AA 7075 disc at low sliding speed (0.0628 m/s and 0.157 m/s) was abrasive wear and oxidative wear at middle sliding speed (0.314 m/s). As sliding speed increases to higher sliding speed (0.471 m/s and 0.628 m/s), adhesive delamination wear dominated the wear process. The tribo oxides layer can efficiently protected the alloy substrate only at sliding speed of 0.314 m/s. At higher sliding speeds, tribo oxides layer were removed quickly once it was formed due to its internal fractures of tribo oxides and lower bonging strength with substrate.

A dynamic analysis model for the drilling riser was established and applied under normal drilling and hang-off conditions by distinguishing the boundary condition. This model was discretized by the FEM and solved by Newmark β method. The correctness of this model was verified through an experiment. Results indicate that the lateral displacement distribution and riser stress increase with the current speed and platform drift distance. A platform that drifts along the current is conducive to counteract the rotation of the upper joint but promotes the rotation of the bottom joint of the riser. A riser that is approximately 2,000 m long under normal drilling condition can withstand the current loads for a 10-year return period. The hang-off riser should be evacuated after being disconnected from the bottom along with the current as soon as possible. In addition, the riser that evacuated under soft hang-off condition can significantly reduce stress but enlarge the rotation angle of the upper flexible joint.

In deep-water drilling for oil and gas, the annular blowout preventer (BOP) is subjected to sustained high pressure or impact loads, causing the concentration of stress in some regions, which can easily cause cracks or fatigue damage. The top cover and housing of the annular BOP are the main pressure-containing parts. Once they fail during the emergency shut-in process, a blowout accident will occur, and there may be casualties and major economic losses. Therefore, the stress concentration regions of the top cover and the housing must be analysed to ensure safe operation. In this study, a high-fidelity approach to monitor the stress was established. This approach combines the theoretical calculation method (TCM), finite-element analysis (FEA) and stress testing experiment (STE). The stress distribution laws of the top cover and housing were measured under the rated working pressure and hydrostatic test pressure. The results indicated that the TCM, FEA, and STE exhibited the same curve trend of stress. Moreover, the FEA results were almost identical to the STE results for the stress values of testing points. The FEA results indicated that there were two critical stress regions in the housing. These were regions where cracks and failures had actually occurred in the past. The main technical contribution of the study is that it may serve as the basis for additional investigations into abandonment evaluation, fatigue analysis, and residual life evaluation.

Interval control valve (ICV) is an important part of intelligent well. An ICV was designed and its flow field characteristic was analyzed by the software CFX. With the increase of the ICV opening, the thickness of laminar bottom layer became thinner and the average velocity of the main flow zone increased. The opening had greater effect on the average velocity than the pressure differential. When the ICV was opened or closed, there might be a great shear resistance due to the large inlet flow rate. There was a velocity stagnation point at the intersection of ICV entrance and its axis. The turbulent kinetic energy decreased gradually with the increase of the ICV opening. It was proved that the ICV had a good flow capacity, and the downhole fluid did not produce large pressure drop when it flew through the ICV. The ICV opening - flow coefficient curve could guide the operation of the ICV to achieve the purpose of accurately regulating the production of a reservoir.

Operation optimization of natural gas pipelines has received increasing attentions, due to such advantages as maximizing the operating economic benefit and the gas delivery amount. This paper provides a review on the most relevant research progress related to the steady-state operation optimization models of natural gas pipelines as well as corresponding solution methods based on stochastic optimization algorithms. The existing operation optimization model of the natural gas pipeline is a mixed-integer nonlinear programming (MINLP) model involving a nonconvex feasible region and mixing of continuous, discrete, and integer optimization variables, which represents an extremely difficult problem to be solved by use of optimization algorithms. A survey on the state of the art demonstrates that many stochastic algorithms show better performance of solving such optimization models due to their advantages of handling discrete variables and of high computation efficiency over classical deterministic optimization algorithms. The essential progress mainly with regard to the applications of the Genetic Algorithm (GA), Particle Swarm Optimization (PSO), Ant Colony Optimization (ACO), Simulated Annealing (SA) algorithms, and their extensions is summarized. The performances of these algorithms are compared in terms of the quality of optimization results and the computation efficiency. Furthermore, the research challenges of improving the optimization model, enhancing the stochastic algorithms, developing an online optimization technology, researching the transient optimization, and studying operation optimization of the integrated energy network are discussed.